1. Field of the Invention
This invention relates to wellbore services, especially the drilling, completion or stimulation of hydrocarbon wells, and in particular to fluids and methods for drilling or drill-in with minimal fluid loss to the overburden or productive pay, hydraulic fracturing of a subterranean formation with minimal loss of fluid to the formation during fracturing, or to gravel packing a subterranean formation with minimal loss of fluid to the formation during gravel packing.
2. Description of Related Art
Hydrocarbons (oil, natural gas, etc.) are obtained from a subterranean geologic formation by drilling a well that penetrates the hydrocarbon-bearing formation. This provides a partial flowpath for the hydrocarbon to reach the surface. In order for the hydrocarbon to be produced there must be a sufficiently unimpeded flowpath from the formation to the wellbore. This flowpath is through the formation rock, which has pores of sufficient size, connectivity, and number to provide a conduit for the hydrocarbon to move through the formation.
One reason why low production sometimes occurs is that the formation is naturally xe2x80x9ctightxe2x80x9d (low permeability), that is, the pore throats are so small that the hydrocarbon migrates toward the wellbore only very slowly. Alternatively, or in combination, the formation or wellbore may be xe2x80x9cdamagedxe2x80x9d by, e.g., dehydration of drilling or drill-in fluid; the presence of certain types of hydrocarbon, i.e. waxes and asphaltenes; and the occurrence of inorganic scale. The common denominator in both cases (damage and tight formations) is low permeability.
Techniques performed by hydrocarbon producers to increase the net permeability of the formation are referred to as xe2x80x9cstimulation.xe2x80x9d Essentially, one can perform a stimulation technique by: (1) injecting chemicals into the wellbore and/or into the formation to react with and dissolve the damage; (2) injecting chemicals through the wellbore and into the formation to react with and dissolve small portions of the formation to create alternative flowpaths for the hydrocarbon (thus rather than removing the damage, redirecting the migrating hydrocarbon around or through the damage); (3) injecting chemicals into the wellbore that will contact drilling or drill-in fluid filter cake that resides along the face of the wellbore thus removing filter cake from the wellbore face; or (4) injecting chemicals through the wellbore and into the formation at pressures sufficient to fracture the formation (xe2x80x9chydraulic fracturingxe2x80x9d), thereby creating a large flow channel though which hydrocarbon can more readily move from the formation and into the wellbore. With respect to stimulation, the present invention is directed primarily to the fourth of these processes, but applies to all four processes in instances where a need to control the rate of treatment fluid lost into the formation is beneficial.
Hydraulic fracturing involves breaking or fracturing a portion of the surrounding strata, by injecting a fluid into a formation through the wellbore, and through perforations if the well has been cased, at a pressure and flow rate sufficient to overcome the minimum in situ stress (also known as minimum principal stress) to initiate or extend a fracture(s) into the formation.
This process typically creates a fracture zone having one or more fractures in the formation through which hydrocarbons can more easily flow to the wellbore.
Since the main functions of a fracturing fluid are to initiate and propagate fractures and to transport a proppant (usually sand, glass or ceramic beads used to hold the walls of the fracture apart after the pumping has stopped and the fracturing fluid has leaked off or flowed back) the viscous properties of the fluids are most important. Many known fracturing fluids comprise a water-based carrier fluid, a viscosifying agent, and the proppant. The viscosifying agent is often a cross-linked water-soluble polymer. As the polymer undergoes hydration and crosslinking, the viscosity of the fluid increases and allows the fluid to initiate the fracture and to carry the proppant. Another class of viscosifying agent is viscoelastic surfactants (xe2x80x9cVES""sxe2x80x9d).
Both classes of fracturing fluids (water with polymer, and water with VES) can be pumped as foams or as neat fluids (i.e. fluids having no gas dispersed in the liquid phase). Foamed fracturing fluids typically contain nitrogen, carbon dioxide, or mixtures thereof at volume fractions ranging from 10% to 90% of the total fracturing fluid volume. The term xe2x80x9cfracturing fluid,xe2x80x9d as used herein, refers to both foamed fluids and neat fluids.
VES-based fracturing fluids, like other fracturing fluids, may leak-off from the fracture into the formation during and after the fracturing process. The VES leak-off is viscosity controlled, and the leak-off rate depends on several factors, including formation permeability, formation fluids, applied pressure drop, and the rheological properties of the VES fluids. Leak-off is particularly problematic in medium to high permeability formations (greater than about 2 mD, especially greater than about 10 mD, most especially greater than about 20 mD). The rate at which fluid leaks off from the fracture generally increases with increasing rock permeability and with increasing net positive pressure differential between the fluid in the fracture and the pore pressure of fluid in the formation. Fluid loss is a term often used for the flow of fracturing fluid into the formation from the fracture. (The terms xe2x80x9cfluid lossxe2x80x9d and xe2x80x9cleak-offxe2x80x9d are used interchangeably herein.) Fluid loss control is a term often used to indicate measures used to govern the rate and extent of fluid loss. The consequence of high fluid loss (also referred to as low fluid efficiency, where fluid efficiency is inversely proportional to the fluid loss into the formation) is that it is necessary to inject larger volumes of a fracturing fluid in order to create the designed fracture geometry, i.e., fracture length and width sufficient to hold all the injected proppant. Use of low efficiency fluids can increase the time and expense required to perform the fracturing operation. U.S. Pat. No. 5,964,295, which is hereby incorporated by reference, describes VES fluids developed in particular for use in low permeability formations and indicates that VES fluids are not normally used in high permeability applications unless the size of the job and the volume of fluids needed are small.
Viscosified fluids are also used in other wellbore services, such as sand control, drilling and completion. Gravel packing and xe2x80x9cdrill-inxe2x80x9d (which is drilling in the productive formation) with special fluids are two techniques that are commonly used to minimize damage to the producing zone during the completion process.
Sand control is the term used to describe the prevention or minimization of the migration of fine, mobile particles during hydrocarbon production. In this connection, xe2x80x9csandxe2x80x9d is used to describe any such particles and the formation need not be a sand or sandstone. Sand control can involve an operation where a device is first placed into the wellbore across the producing interval that serves to filter fine, mobile formation particles from the produced oil, water, or gas. This device is often called a sand control screen. Frequently, a graded material (such as 20/40 mesh sand) is placed such that it completely occupies the annular space between the exterior of the screen and the sand face. This xe2x80x9cgravel packxe2x80x9d is designed to further filter mobile particles from the produced oil, water, or gas so that those particles do not cause screen blocking or erosion. The gravel is placed in this annular gap by pumping a slurry which is typically an aqueous fluid containing the gravel. This slurry is injected from the surface and is diverted into the annulus once the fluid reaches the depth of the screen. The carrier fluid often contains materials to viscosify it and enhance the performance of the slurry. The viscosifying materials may include polymers (such as guar or hydroxypropylguar) and a crosslinker. As the polymer undergoes gelation and crosslinking, the viscosity of the fluid increases and allows the fluid to carry the gravel (commonly sand, or glass or ceramic beads). Another class of gravel packing fluids comprises water or brine as a carrier fluid, a viscoelastic surfactant, and a gravel. The viscoelastic surfactant provides a viscosity and elasticity high enough to carry gravel. These polymer-free gravel carrier fluids have some of the same high fluid loss issues as the aforementioned polymer-based fracturing fluids, especially in high permeability formations, as described in U.S. Pat. No. 5,964,295, which is hereby incorporated by reference.
To overcome the tendency of high fluid loss in polymeric and VES-based fracturing fluids and gravel carrier fluids under some conditions, various fluid loss control additives (FLAs) have been tried. Silica, mica, and calcite, alone, in combination, or in combination with starch, are known to reduce fluid loss in polymer-based fracturing fluids, by forming a filter cake, on the formation face, which is relatively impermeable to water, as described in U.S. Pat. No. 5,948,733. Use of these FLAs alone in a VES-based fracturing fluid, however, has been observed to give only modest decreases in fluid loss from VES-based fracturing and gravel-packing fluids, as described in U.S. Pat. No. 5,929,002, which is hereby incorporated by reference. It would be desirable to find an FLA that would be much more effective in VES-based fluids.
Nguyen et al., U.S. Pat. No. 5,680,900 teaches the crosslinking of guar in solution, the shearing of the crosslinked guar to form a fine particulate slurry, and injecting the slurry into a formation. The slurry imparts reduced fluid loss to fluids containing the slurry or from later fluids injected into the formation. Nguyen teaches that the FLA must be precrosslinked, then finely chopped up, and then added to a completion or stimulation fluid. Moreover, Nguyen teaches the use of enormous concentrations of the FLA, on the order of 25% by weight of the chopped crosslinked gel materials.
Jones et al., UK Pat. No. GB2,332,224 teaches the use of a wellbore service fluid for water control operations comprising a viscoelastic surfactant and very high concentrations of a cross-linkable water-soluble polymer and a cross-linking agent. Inorganic ions or polar organic molecules can be used as crosslinkers. The objective of the Jones patent is to enhance gel strength of the viscoelastic surfactant (VES)-based wellbore service fluid. Jones et al. does not discuss the use of such fluids to minimize fluid loss during drilling, drill-in, completion or stimulation.
Polymer-free drilling, drill-in, completion, fracturing and gravel packing fluids have very poor fluid efficiency and a tendency to leak off into medium to high permeability media (especially greater than approximately 2 mD). These problems stem from the lack of a wall building component for fluid loss control; that is, all leak-off control in such systems is due only to viscous forces and the compressibility of reservoir fluids. In medium to high permeability formations, increasing wellbore service fluid viscosity alone may not suffice to reduce fluid loss to practical levels. Although VES-based materials can be used alone, it would often be better to increase fluid loss control properties. As mentioned before, conventional wall-building fluid loss control additives alone, such as those containing silica, mica, limestone, rock salt, kaolin, talc, alumina or mixtures thereof, do not perform well in polymer free fluids because there is a period of high leak-off (spurt) before a filter cake is formed and because the filter cake may be too permeable to the polymer free fluid. The inventors have found that conventional viscosifying materials, such as polymers, do not create enough viscosity (for example starch), or themselves leak off into the formation (for example uncrosslinked guar), when used to control early leak-off in polymer free systems.
Therefore, it is desirable to have a VES-based drilling, drill-in, gravel packing or fracturing fluid comprising one or more FLAs which reduce fluid loss, especially spurt, during drilling, drill-in, gravel packing and fracturing operations.
The preceding and following discussions are in terms of hydrocarbon-producing wells, but are also applicable to other types of wells, such as water-producing wells or water-injection wells.
It would be suitable that FLAs for polymer free wellbore service fluids form a filter cake rapidly and do not penetrate into the formation. We have discovered that adding small amounts of a crosslinker and a crosslinkable polymer to a polymer free fluid results in effective fluid loss control.
In one embodiment, the present invention is directed to a wellbore service fluid comprising a carrier fluid, a viscoelastic surfactant, and a fluid loss control additive comprising at least one polymer and at least one crosslinker; said polymer and said crosslinker forming a crosslinked polymer; said crosslinked polymer being present in a concentration of less than about 15 pounds per thousand gallons; and said crosslinked polymer comprising a three-dimensional polymer network or gel aggregates large enough to form a filter cake and reduce fluid loss. More than one polymer and/or more than one crosslinker can be used. The polymer(s) and the crosslinker(s) can form the crosslinked polymer(s) before they are added to the carrier fluid, as soon as they are added to the carrier fluid, after being added to the carrier fluid but before injection into the wellbore, or during or after injection into the wellbore.
In other embodiments, the present invention is directed towards use of the above-described wellbore service fluid in fracturing, gravel packing, drill-in and drilling to reduce fluid loss in these procedures. The method of fracturing comprises providing the wellbore fluid and injecting it into a formation at a pressure sufficiently high to fracture the formation, to form a fractured formation. The FLAs of the present invention can be used in a pre-pad stage, in the pad stage, in the pad and the proppant stages, or in the pad and in some of the proppant stages, in particular the proppant stages that immediately follow the pad. The method of gravel packing comprises providing the wellbore fluid and gravel, and injecting the gravel carrying fluid into the wellbore under conditions that will result in gravel being retained in the annular space between a screen and the formation face. In the drill-in or drilling methods, the fluid loss rate of solids free drilling fluids and drill-in fluids can be reduced by preparing a drilling or drill-in fluid comprising the above-described wellbore fluid and circulating the fluid through the drill string and up the annulus in a manner that removes drill cuttings and lubricates the drill string.
It has been found that the fluids of the present invention exhibit reduced fluid loss during well drilling, completion (including drill-in) or stimulation operations.